There are numerous methods, techniques and innovations designed to improve the oil and gas drilling process. Many of these involve feedback of various measured downhole parameters that are communicated to the surface to enable the driller to more efficiently, safely or economically drill the well. For example, U.S. Pat. No. 6,968,909 to Aldred et al. teaches a control system that combines measurement of downhole conditions with certain aspects of the operation of the drillstring. These downhole measurements are conveyed to the surface by well-known standard telemetry methods where they are used to update a surface equipment control system that then changes operation parameters. Closed loop two-way communication techniques like this, however, rely on the adequate detection at the surface of the telemetered parameters.
It is standard in the drilling industry to control certain parameters of the downhole telemetry transmitter by downlinking appropriate commands from the surface. For example, changing the downhole drilling fluid pressure in a prescribed manner by changing the flow rate of the drilling fluid and subsequently monitoring this by a downhole pressure gauge is a common technique. Problems associated with this and similar downlinking techniques include false detection, slowing of the drilling process and the need to include human intervention in the process.
There are at present two standard telemetry techniques in common use—data conveyed via pressure waves in the drilling fluid and data conveyed via very low frequency electromagnetic waves, both originating at a downhole transmitter. Another telemetry technique beginning to emerge in the drilling arena is to convey the data via acoustic waves travelling along the drillpipe within certain bands of frequencies (or passbands). All three technologies suffer from noise associated with the drilling operation, and all three similarly suffer signal attenuation at the surface as the well bore increases in length.
The design of acoustic systems for static production wells has been reasonably successful, as each system can be modified within economic constraints to suit these relatively long-lived applications. The application of acoustic telemetry for data transfer from downhole to an acoustic receiver rig at the surface in real-time drilling situations, however, is less widespread. Acoustic telemetry is an emerging technology and has as-yet unresolved problems related to the increased in-band noise due to certain drilling operations, and unwanted acoustic wave reflections associated with downhole components such as the bottom-hole assembly (or “BHA”), typically attached to the end of the drillstring. The problem of communication through drillpipe is further complicated by the fact that drillpipe has heavier tool joints than production tubing, resulting in broader stopbands; this entails relatively less available acoustic passband spectrum, making the problems of noise and signal distortion even more severe. As the well is drilled and the amount of drillpipe increases there is a general degradation of the available acoustic passband properties, primarily through two effects: the non-identical dimensions of the drillpipes due to manufacturing tolerances and recuts of tool joints (these will narrow and distort the acoustic passband); the acoustic signal attenuation increases directly with the number of drillpipes. The amount of drillpipe is directly related to the ‘measured depth’ (MD), in contrast to the ‘true vertical depth’ (TVD). TVD is the vertical depth used to calculate hydrostatic pressure.
Attenuation is also a function of the amount of wall contact with the drillpipe because this contact provides a means of extracting energy from acoustic waves travelling along the pipe. Typical attenuation values may range from 12 dB to 35 dB per kilometre.
Noise from many sources must also be dealt with. For example, the drill bit, mud motor and the BHA and pipe all create acoustic noise, particularly when drilling. The downhole noise amplitude generally increases as rotation speed of the drillpipe and/or the drilling rate of penetration increases. On the surface, noise originates from virtually all moving parts of the rig. Dominant noise sources include diesel generators, rotary tables, top drives, pumps and centrifuges.
Thus, it is evident that channel issues and noise problems will increase with the measured depth, drilling rate and rotary speed.
In summary, the challenges to be met for acoustic telemetry in drilling wells include:                Restricted channel bandwidth due to the drillstring passband structure        Channel centre shifts        Dynamically changing channel properties        Downhole noise due to drillpipe movements        Downhole noise due to mud motor and/or drill bit activity        Surface noise due to rig components such as diesel generators, rotating tables, and top drives        